Various different flowmeters are used in industry to provide information about the flow rate of multiphase fluids. The fluids that are metered can include mixtures of liquids and gases. This situation is commonly encountered in the oil and gas industry, where the fluids produced are commonly a mixture of oil, water, and gas. However, the need to meter multiphase fluids also occurs in other industries as well. Flowmeters are also important in applications that do not involve multiphase fluids.
One type of flowmeter is a Coriolis flowmeter. A Coriolis flowmeter includes an electronic transmitter and a vibratable flowtube through which fluid to be metered can be passed. The transmitter maintains flowtube vibration by sending a drive signal to one or more drivers and performs measurement calculations based on signals from a pair of sensors that measure movement of the flowtube. The physics of the device dictate that Coriolis forces act along a section of the flowtube between the sensors, resulting in a phase difference between the generally sinusoidal sensor signals. This phase difference is generally proportional to the mass flow rate of the fluid passing through the measurement section of the flowtube. Thus, the phase difference provides a basis for a mass flow measurement of fluid flowing through the flowtube. The frequency of oscillation of the flowtube of a Coriolis meter varies with the density of the process fluid in the flowtube. The frequency value can be extracted from the sensor signals so that the density of the fluid can also be obtained by analyzing the sensor signals.
Coriolis meters are widely used throughout various different industries. The direct measurement of mass flow is frequently preferred over volumetric-based metering, for whereas the density and/or volume of a material may vary with temperature and/or pressure, mass is unaffected. This is particularly important in the oil and gas industry, where energy content and hence product value is a function of mass. The term ‘Net Oil’ is used in the oil and gas industry to describe the oil flow rate within a three-phase or a liquid (oil/water) stream. A common objective in the oil and gas industry is to determine the net oil produced by each well in a plurality of wells because this information can be important when making decisions affecting production from an oil and gas field and/or for optimizing production from an oil and gas field.
The inclusion of gas in a liquid stream introduces errors in the mass flow and density measurements of a Coriolis meter. Laboratory trials can be used to characterize how mass flow rate and density errors relate to other parameters, such as the observed flow rate and observed reduction in density from that of the pure fluid. These trials can be used to develop empirical models that provide corrections to account for some of the error associated with the presence of multiphase fluids including gas and liquid phases. These empirically-based corrections can result in improved performance of Coriolis meters in field operations. Additional details concerning use of Coriolis meter to meter multiphase fluids are provided in U.S. Pat. Nos. 6,311,136; 6,505,519; 6,950,760; 7,059,199; 7,313,488; 7,617,055; and 8,892,371, the contents of which are hereby incorporated by reference.
In many conventional Coriolis meters the frequency of oscillation of the flowtube is calculated by measuring the time between zero crossings on the sensor signals. Fourier techniques are commonly used to calculate the amplitude and phase of the flowtube vibration. For example, FIG. 1 illustrates a quadrature technique that has been used in many conventional Coriolis meters. In this technique, the sensor signals are multiplied by a quadrature sine wave and also a quadrature cosine wave. The quadrature products are integrated over a cycle (the length of which is based on the frequency calculation) to yield Is for the integral obtained by integrating the sine product and Ic for the integral obtained by integrating the cosine product. The phase of each sensor signal is calculated as the arctan of (Ic/Is). The amplitude of each sensor signal is calculated as the square root of (Is2+Ic2). The calculated frequency and phase provide the basis for measuring density of the fluid and mass flow rate. As the density of the fluid increases, the frequency of the sensor signal will decrease. Also, the difference in the phase of the two sensor signals will increase as the mass flow rate increases. In some Coriolis meters, the calculated frequency, amplitude, and phase are further used to generate a synthesized drive signal that is used to drive oscillation of the flowtube.
Because the frequency of the flowtube changes (e.g., in response to changes in the density of the fluid flowing through the flowtube), the time between zero crossings and the calculated frequency also changes during operation of the meter. Consequently, conventional Coriolis meters update the values for the sine and cosine functions each new cycle, or in some cases every half cycle. For example, the values for the quadrature functions are commonly recalculated each half cycle using the new calculated frequency based on the latest zero crossings. Also, when the beginning and end of each cycle are constrained to be at zero crossings, as in the technique illustrated in FIG. 1, there are no updates to the frequency, amplitude, or phase at intermediate points between the zero crossings.
The present inventor has made various improvements, which will be described in detail below, applicable to the field of Coriolis flowmeters and applicable to the field of net oil and gas testing.